The embodiments herein relate to sealant compositions for use in subterranean formation operations.
A natural resource, such as oil, residing in a subterranean formation may be recovered by drilling a well into the subterranean formation. The well may be isolated from the surrounding subterranean formation using an operation known as cementing. In a cementing operation, a cement sheath around a casing (or liner string) may be placed within the well. The cement sheath is formed by pumping a cement slurry through the bottom of the casing and out through the annulus between the outer casing wall and the formation face of the wellbore. The cement slurry then cures in the annular space, thereby forming a sheath of hardened cement that, inter alia, supports and positions the casing in the wellbore and bonds the exterior surface of the casing to the subterranean formation.
The subterranean formation may thereafter be stimulated for the production of oil through the cemented wellbore. In some operations, the subterranean formation may be stimulated by a hydraulic fracturing treatment. In hydraulic fracturing treatments, a treatment fluid is pumped past the cement sheath into a portion of the subterranean formation at a rate and pressure such that the subterranean formation breaks down, and one or more fractures are formed. Typically, particulate solids, such as graded sand, are suspended in a portion of the treatment fluid and then deposited into the fractures. These particulate solids, or “proppant particulates,” serve to prop open the fracture (e.g., keep the fracture from fully closing) after the hydraulic pressure is removed. By keeping the fracture from fully closing, the proppant particulates aid in forming conductive paths through which produced fluids, such as oil, may flow.
During oil production from a subterranean formation, water or undesirable gas may seep from the formation and accompany the produced oil. The production of water or unwanted gas with the produced oil may present major problems, including a significant reduction of oil production, the need for costly remedial actions, downtime in production, and the like. The water may seep into the well with produced oil from any subterranean zone in communication with the oil producing formation, such as, for example, through a fracture, a high-permeability streak, a high-permeability zone, and the like, or may be the result of water coning, water cresting, lateral channeling, and the like. Additionally, the source of the water may be from waterflood techniques. Likewise, although in some instances gas may be desirably produced from a subterranean formation, certain gases may be undesirable and production at high gas/oil ratios may decrease the productive life of the subterranean formation. Unwanted gas may seep into the well with produced oil due to a variety of causes, including fractures in the formation, gas coning, gas channeling, and the like as a result of the high mobility of gas in the formation.
Conformance control treatments may be used to reduce the influx of water (“water shutoff”) or gas (“gas shutoff”) with produced oil. As used herein, the term “conformance control” and any variants thereof (e.g., “conformance treatments” or “conformance control treatments”) refers to sealant treatments involving the placement of a material, or a “conformance material” or “conformance composition,” into a wellbore and adjacent to a water-bearing or gas-bearing portion of a subterranean formation that is capable of at least partially preventing, reducing, or otherwise controlling the influx of the water or gas into the wellbore. Such conformance materials may include, but are not limited to, particulates, gels, sealants, blocking polymers, and the like. Conformance control treatments may enhance recovery efficiency and reduce costly downtime or separation techniques required for separating the oil from unwanted produced fluids.
Subterranean formations often require conformance treatments at depleted or low pressure zones, where the hydrostatic pressure coupled with pumping pressure in the wellbore may exceed the fracture gradient of the formation, thus promoting the formation of unplanned, induced fractures and significant loss of drilling or other treatment fluids, particularly those having high densities. Conformance fluids may additionally be lost into these fractures or other areas of high permeability if they are themselves high-density fluids or are delivered in high-density fluids. Conformance fluids foamed due to the presence of gas within the fluid have thus been used to achieve reduced densities. The addition of gas to achieve foamed conformance materials may not always be sufficient to overcome the high density constituents often included in conformance fluids. Moreover, the presence of the gas and the high density constituents together may cause the foamed conformance fluids to reach extreme viscosities that are unmanageable in terms of mixing and pumping. Furthermore, the equipment requirements for transporting and injecting gases into fluids makes the technology less accessible. Thus, although the density of the conformance fluid may be reduced, it may not be practicably used.